Physical Principles involved in the Recovery of Heavy Oil and Oil Sands Bitumen
Oil Viscosity
Compared to light, conventional oil, heavy oil and oil sands bitumen have greater density and are more viscous, that is, they do not flow as easily in the subsurface reservoirs in which they are found. The viscosity of heavy oil and bitumen is so high as to prevent them from flowing at commercial production rates or to make them immobile at initial reservoir conditions.
“The viscosity of heavy oil and bitumen is so high as to prevent them from flowing at commercial production rates or to make them immobile at initial reservoir conditions.”
Heavy oils have viscosities that typically range from a few hundred centipoise (cP) to 10s of thousands, and bitumen viscosity ranges from about 100,000 to several million cP.
Heat
The viscosity of these oils is highly sensitive to temperature and, by increasing the temperature of the oil from initial reservoir conditions to steam temperature, the oil viscosity can be reduced oil by as much as 6 orders of magnitude from millions of cP to less than 10 cP.
“… by increasing the temperature of the oil from initial reservoir conditions to steam temperature, the oil viscosity can be reduced oil by as much as 6 orders of magnitude…”
Importantly, in order to heat the oil in the reservoir, it is also necessary to heat to the same higher temperature the formation rock and water that are also present. Thus, the more oil that is present in the reservoir relative to the rock and other fluids, the more efficient the energy may be used to heat the oil in relation to the other materials. It follows that the higher the formation porosity, and the higher the oil saturation in the formation, the more efficient will be the utilization of energy to mobilize oil.
Solvents
The oil viscosity may also be reduced by mixing the viscous material with a lighter, lower viscosity material (solvent) with which it is soluble. Solvent dilution in oil may also be used to reduce oil viscosity by as much as 4 orders of magnitude.
“Solvent dilution in oil may also be used to reduce oil viscosity by as much as 4 orders of magnitude.”
Solvents used are often light hydrocarbons such as propane and butane or gas condensate containing a mixture of light aliphatic hydrocarbons. Some promising recovery methods employ a combination of mild heating and solvent dilution to achieve the desired lower oil viscosity.
It should be noted that the lower the viscosity of the oil at original reservoir conditions, the less energy or solvent is required to reduce its viscosity to make it flow at commercial rates. Thus, the economics of heavy oil production will always favor the medium gravity oils over bitumen that has orders of magnitude greater viscosity.
Rock Properties
Porosity
The porosity of a reservoir, often being between 25 and 33 %, is a measure of the amount of pore space that exists that contains the oil and water naturally present. The rest of the bulk volume (67 to 75 %) is made up of rock, either sandstone or carbonate. The majority of heavy oil and oil sands that have been commercially exploited is found in sandstones.
Permiability
Absolute permeability is the other important property of reservoir rock as this is a measure of the ability of the rock transmit fluids through it. The higher the permeability, the more easily a given fluid will be able to flow through the rock. Heavy oil and oil sand reservoirs often have permeabilities of several Darcies.
“What is critically important is the ratio of the absolute permeability to the oil viscosity …”
What is critically important is the ratio of the absolute permeability to the oil viscosity: the higher the ratio, the greater the propensity for flow of the fluid through the rock. The water that is naturally present is often located in direct contact with the rock surface (water wet) and is usually immobile as it held in place by capillary pressure. Water represents about 15 to 25 % of the pore space or about 4 to 8 % of the bulk volume. The rest of the pore space, 75 to 85 %, is filled with oil. This represents about 19 to 28 % of the bulk volume.
“The other factor that has a large bearing on the rate at which oil can move through a reservoir and reach production wells is known as relative permeability.”
Oil Relative Permeability
The other factor that has a large bearing on the rate at which oil can move through a reservoir and reach production wells is known as relative permeability. This concept is more difficult to understand and is often given insufficient consideration. Basically, relative permeability is a measure of the ability of one fluid to flow in the presence of other fluids that occupy part of the pore space.
The relative permeability to oil is a function of the oil saturation as is the case for water and gas relative permeabilities. Water and/or gas flowing in the reservoir pore space has a negative effect on the ability of oil to flow: the fluids compete with other for flow capacity in a non-linear manner. Thus, by reducing or eliminating water and/or gas flow in the reservoir, the flow of oil is promoted. This is particularly relevant when considering steam injection oil recovery where, after the steam has condensed, the steam condensate is flowing with the heated and mobile oil, but its very presence inhibits the ability of the oil to flow.
“Water and steam have the advantage of being able to carry large amounts of heat per unit mass, but the water does have the disadvantage of restricting oil flow by its very presence …”
Water and steam have the advantage of being able to carry large amounts of heat per unit mass, but the water does have the disadvantage of restricting oil flow by its very presence and if the SOR is in the range of 3 to 5, the water saturation in the pore space is considerable and this causes a lower oil saturation to exist in the part of the reservoir in which mobile fluids are flowing. This relative permeability impairment that is experienced with steam injection is not a concern in the case of solvent injection as the solvent becomes part of the oil phase and the amount of solvent needed is in a smaller ratio to the oil of around 1:1 or less. Of course, the volume of the oil phase has been increased by the mixing with solvent and so the flow rate of oil is reduced but not to the same extent as in the case of steam injection.
Heat Transfer and Energy Efficiency
There is no doubt that injecting steam into a reservoir is the most effective way of transferring energy to a formation. This is due to the almost unique character of water that gives it both very high sensible and latent heats allowing it to carry substantial energy for heating. The condensation of steam in the formation releases a tremendous amount of energy but as mentioned previously, the production of steam condensate along with produced oil also removes substantial amounts of energy from the formation.
“Recovery processes that rely on conduction heating are limited by the composite thermal conductivity of the formation and the amounts of energy that can be transferred by conduction are almost an order of magnitude lower than the convective heat transfer associated with steam injection in a high permeability reservoir.”
Recovery processes that rely on conduction heating are limited by the composite thermal conductivity of the formation and the amounts of energy that can be transferred by conduction are almost an order of magnitude lower than the convective heat transfer associated with steam injection in a high permeability reservoir.
For example, the practical energy transfer by conduction from a 1000-metre-long resistive electric heater is about 1 MW but in SAGD if the same horizontal well is able to inject 300 m3/d of steam at 2 MPa pressure, approximately 8 MW of energy is transferred by convection. Electromagnetic heating, for example radio frequency heating, relies primarily on excitation of water that has high dielectric constant, the energy being absorbed by the water raising its temperature and then transferring heat from the water to the surrounding rock and oil.
Fluid Phase Behaviour
It is worth noting that solubility of gases in oil and water is reduced as temperature increases. This is also true of the amounts of solvents that can be mixed with oil to achieve dilution and viscosity reduction. Therefore, in the case of solvent injection, a combination of milder heating to temperatures below 100 °C along with solvent dilution is often contemplated to achieve satisfactory oil viscosity reduction.
“It is also important to recognize that achievement of fluid equilibria is not instantaneous in porous media.”
It is also important to recognize that achievement of fluid equilibria is not instantaneous in porous media. The time that it takes for fluids to dissolve and mix means that they are free to travel in their original pure form prior to mixing and this may significantly affect the distribution of fluids in the reservoir. In the case of soluble gases such as carbon dioxide, which have significant solubility in both oil and water, it is very important not to ignore the solubility in water. The introduction of non-condensable gases or solvent vapour into a steam chamber is known to affect the saturation temperature of the mixture. Consideration of this effect is important for calculating the heat transfer to the vapour chamber edge and to the cap rock.
Thermal Diffusion and Molecular Diffusion
It is well known that the rate of thermal diffusion in a porous medium is approximately an order of magnitude greater than molecular diffusion.
“It is well known that the rate of thermal diffusion in a porous medium is approximately an order of magnitude greater than molecular diffusion.”
This means that processes that rely heavily on diffusion of material into heavy oil or bitumen to reduce its viscosity will have lower rates of mobilization of the oil and therefore lower production rates. It is also known that the rates of molecular diffusion increase with increasing temperature so that even mild heating can raise the rates of molecular diffusion and the reduction in viscosity achieved by solvent mixing combined with viscosity reduction from the modest temperature increase can raise production rates.
Formation Geology and Geomechanics
All oil recovery processes including thermal recovery processes for heavy perform best in clean, homogeneous formations, that is, those without shale and clay present. In the case of gravity drainage processes such as SAGD, there is a minimum formation thickness that allows sufficient height of oil producing reservoir above the horizontal wells to provide enough fluid head and reserves to make the process technically and economically viable.
“All oil recovery processes including thermal recovery processes for heavy perform best in clean, homogeneous formations …”
The absence of reservoir impairments also promotes superior recovery process performance. Such impairments include lean zones with high water saturation, inclined heterolithic strata (IHS beds), bottom water, top water, and top gas. The pexistence of shale and other barriers to vertical flow of fluids is also detrimental to recovery processes and especially to gravity drainage processes.
“Dilation of the formation increasing its permeability to injected fluids may have a significant effect on in-situ recovery process performance.”
Dilation of the formation increasing its permeability to injected fluids may have a significant effect on in-situ recovery process performance. It has been demonstrated that marked increases in absolute and relative permeability occur when high injection pressures are used in the McMurray formation at Athabasca (Abbasi and Chalaturnyk, 2016; Collins, 2007). This will affect the ability of hot fluids to penetrate the cold formation near the edge of the steam/vapour chamber that in turn will influence the rate of growth of the heated zone and the oil production rate. Using higher pressure to raise steam temperature and increase dilation effects must be balanced with the ability of the cap rock to contain the fluids.
Dr. Thomas G Harding
Tom Harding holds BSc and MSc degrees in Chemical Engineering from the University of Calgary and a PhD in Petroleum Engineering from the University of Alberta. He has over 30 years of industry experience in a variety of oil and gas project evaluations, development and production operations. He is a former head of the Chemical & Petroleum Engineering Department at the University of Calgary where he conducted research into improved recovery methods for heavy oil and oil sands, produced water treatment and production of biofuel from waste biomass. Dr. Harding has taught courses in petroleum production engineering and non-renewable resource Dr. Thomas G. Harding development. He has been retired since 2018.